In the course of assessing and producing hydrocarbon bearing formation and reservoirs, it is important to acquire knowledge of formation and formation fluid properties which influence the productivity and yield from the drilled formation. Typically such knowledge is acquired by methods generally referred to as “logging”.
Logging operations involve the measurement of a formation parameter or formation fluid parameter as function of location, or more specifically depth in a wellbore. Formation logging has evolved to include many different types of measurements including measurements based on acoustic, electro-magnetic or resistivity, and nuclear interactions, such as nuclear magnetic resonance (NMR) or neutron capture.
NMR measurements are commonly used in the wellbore to probe the NMR decay behavior of the stationary fluid in the reservoir rock. During these measurements, magnetic fields are established in the formation using suitably arranged magnets. The magnetic fields induce nuclear magnetization, which is flipped or otherwise manipulated with on-resonance radio frequency (RF) pulses. NMR echoes are observed, and their dependence on pulse parameters and on time is used to extract information about the formation and the fluids in it.
In particular, NMR has been used in the oilfield industry to obtain information and parameters representative of bound fluids, free fluids, permeability, oil viscosity, gas-to-oil ratio, oil saturation and water saturations. All these parameters can be derived from measurements of spin-spin relaxation time, often referred to as T2, spin-lattice relaxation time (T1), and self-diffusion coefficient (D) of the molecules containing hydrogen contained in formation fluids.
On the other hand, fluids are routinely sampled in the well bore with the help of so-called formation testers or formation fluid sampling devices. An example of this class of tools is Schlumberger's MDT™, a modular dynamic fluid testing tool. Such a tool may include at least one fluid sample bottle, a pump to extract the fluid from the formation or inject fluid into the formation, and a contact pad with a conduit to engage the wall of the borehole. When the device is positioned at a region of interest, the pad is pressed against the borehole wall, making a tight seal and the pumping operation begins.
With the pumping a flow in the formation is induced by extracting fluid from the formation through the conduit. The fluid flowing through the tool is analyzed in situ using electrical, optical or NMR based methods. Typically when the fluid is assumed to be ‘pure’ reservoir fluid, i.e., when having acceptable levels of mud or other contaminants, a sample of the fluid is placed into the sample bottle for later analysis at a surface laboratory. The module is then moved to the next region of interest or station.
Fluid flow into the borehole is also routinely produced using dual packer arrangements, which for example isolate sections of the borehole during fluid and pressure testing, essentially in the same manner as described for the MDT tool described above. By reversing the flow direction dual packer arrangements offer the possibility of conducting fracturing operations which are designed to fracture the formation around the isolated section of the borehole.
When specifically attempting to inject rather than extract fluid from the formation, a testing tool may require modifications such as described for example in the co-owned U.S. Patent Application 2006/0000606. The tool described therein is a formation tester for open hole formations incorporating a drill bit to drill through the mudcake which accumulates on the wall of the well bore or through zones damaged or contaminated by the drilling process. The tool as described in U.S. 2006/0000606 is capable of injecting fluid into the formation surrounding wellbore for various purposes such as fracturing the formation near the wellbore.
It is further well established to mount logging tools on either dedicated conveyance means such as wireline cables or coiled tubing (CT) or, alternatively, on a drill string which carries a drill bit at its lower end. The latter case is known in the industry as measurement-while-drilling (MWD) or logging-while-drilling (LWD). In MWD and LWD operations the parameter of interest is measured by instruments typically mounted close behind the bit or the bottom-hole assembly (BHA). Both, logging in general and LWD are methods known as such for several decades and hence are believed to require no further introduction.
Applications and measurements designed to exploit the flow generated by tools such as the above formation testing tools in combination with NMR type measurements are described in a number of documents. One example of these published documents is the co-owned U.S. Pat. No. 7,180,288 to Scheven. Another detailed description of possible NMR-based methods for the purpose of monitoring flow and formation parameters can be found in the co-owned U.S. Pat. No. 6,642,715 to Speier et al. and U.S. Pat. No. 6,856,132 to Appel et al. A tool which combines a fluid injection/withdrawal tool with a resistivity imaging tool is described for example in the co-owned U.S. Pat. No. 5,335,542 to Ramakrishnan et al. Borehole tools and methods for measuring permeabilities using sequential injection of water and oil is described in the co-owned U.S. Pat. No. 5,269,180 to Dave and Ramakrishnan and in the co-owned U.S. Pat. No. 7,221,158 to Ramakrishnan. In the co-owned U.S. Pat. No. 5,497,321 to Ramakrishnan and Wilkinson, the authors suggest a method to compute fractional flow curves using resistivity measurements at multiple radial depths of investigation.
In a paper prepared for presentation at the SPWLA 1st Annual Middle East Regional Symposium, Apr. 15-19, 2007, Gilles Cassou, Xavier Poirier-Coutansais and one of the inventors of the present invention, Raghu Ramamoorthy, demonstrate that the combination of advanced-NMR fluid typing techniques with a dual-packer fluid pumping module can greatly improve the estimation of the saturation parameter in carbonate rocks. The ability to perform 3D-NMR stations immediately before and after pump-outs yields both the water and oil saturations (Sw,Sxo) independently of lithology, resistivity, and salinity, in a complex carbonate environment.
However, the method as demonstrated suffers from a number of limitations which makes it difficult to conduct reliable and accurate measurements. Both tools have to be accurately positioned at the same depth at different times. The two 3D-NMR acquisitions must be performed at exactly the same depth as the sampling operation for the manipulation of the formation to be reflected in the 3D-NMR measurement. Given that both tools need to be moved up and down the wellbore to position them correctly—and given further that the uncertainty in tool positioning is at least as large as the dimensions of a typical NMR antenna—the tested implementation as described is not optimal. Moreover, operational problems dictate that the tests cannot be performed by the probe directly because it becomes then more difficult to ensure that the NMR antenna is positioned exactly over the test interval, instead the dual packer configuration has to be used.
Furthermore, the time to unset the dual packers and move the NMR tool down to the correct position at the test interval is about 10 minutes. A typical 3D-NMR measurement may require another 15 minutes of time at the station. If significant re-invasion occurs during this time, the post-pumpout 3D-NMR data is affected and can no longer be correlated with the flow regime as induced by the tool.
In view of the known art, it is therefore seen as one object of the invention to improve and enhance known apparatus and methods for characterizing formations using induced flow in the formation. It is seen as another object to provide more and better methods of determining characteristic formation and formation fluid properties using measuring apparatus having a volume of investigation overlapping or co-located with the volume in which induced flow occurs.